Methods of improving hydraulic fracture network

ABSTRACT

The complexity of a fracture network may be enhanced during a hydraulic fracturing operation by monitoring operational parameters of the fracturing job and altering stress conditions in the well in response to the monitoring of the operational parameters. The operational parameters monitored may include the injection rate of the pumped fluid, the density of the pumped fluid or the bottomhole pressure of the well after the fluid is pumped. The method provides an increase to the stimulated reservoir volume (SRV).

This application claims the benefit of U.S. patent application Ser. No.61/664,595, filed on Jun. 26, 2012.

FIELD OF THE INVENTION

The invention relates to a method of hydraulic fracturing andparticularly to a method of improving the total surface area of acreated or enlarged fracture and/or the complexity of the hydraulicfracture by altering stress conditions in the reservoir.

BACKGROUND OF THE INVENTION

Hydraulic fracturing is a stimulation process for creatinghigh-conductivity communication with a large area of a subterraneanformation. The process increases the effective wellbore area within theformation in order that entrapped oil or gas production can beaccelerated. The efficiency of the process is often measured by thestimulated reservoir volume (SRV) of the formation.

During hydraulic fracturing, a fracturing fluid is pumped at pressuresexceeding the fracture pressure of the targeted reservoir rock in orderto create or enlarge fractures within the subterranean formationpenetrated by the wellbore. The fluid used to initiate hydraulicfracturing is often referred to as the “pad”. In some instances, the padmay contain fine particulates, such as fine mesh sand, for fluid losscontrol. In other instances, the pad may contain particulates of largergrain in order to abrade perforations or near-wellbore tortuosity.

Once the fracture is initiated, subsequent stages of fluid containingchemical agents, as well as proppants, may be pumped into the createdfracture. The fracture generally continues to grow during pumping andthe proppants remain in the fracture in the form of a permeable “pack”that serves to “prop” the fracture open. Once the treatment iscompleted, the fracture closes onto the proppants. Increasing thefracturing fluid pressure ultimately causes an increase in the leak-offrate of the fluid through the faces of fractures which improves theability of the proppant to pack within the fracture. Once the treatmentis completed, the fracture closes onto the proppants. The proppantsmaintain the fracture open, providing a highly conductive pathway forhydrocarbons and/or other formation fluids to flow into the wellbore.

The treatment design of a hydraulic fracturing operation for aconventional reservoir generally requires the fracturing fluid to reachmaximum viscosity as it enters the fracture. The viscosity of the fluidaffects fracture length and width.

The viscosity of most fracturing fluids may be attributable to thepresence of a viscosifying agent, such as a viscoelastic surfactant or aviscosifying polymer. An important attribute of any fracturing fluid isits ability to exhibit viscosity reduction after injection. Lowviscosity fluids known as slickwater have also been used in thestimulation of low permeability formations, including tight gas shalereservoirs. Such reservoirs often exhibit a complex natural fracturenetwork. Slickwater fluids typically do not contain a viscoelasticsurfactant or viscosifying polymer but do contain a sufficient amount ofa friction reducing agent to minimize tubular friction pressures. Suchfluids, generally, have viscosities only slightly higher thanunadulterated fresh water or brine. The presence of the frictionreduction agent in slickwater does not typically increase the viscosityof the fluid by more than 1 to 2 centipoise (cP).

To effectively access tight formations, wells are often drilledhorizontally and then subjected to one or more fracture treatments tostimulate production. Fractures propagated with low viscosity fluidsexhibit smaller fracture widths than those propagated with higherviscosity fluids. In addition, low viscosity fluids facilitate increasedfracture complexity in the reservoir during stimulation. This oftenresults in the development of greater created fracture area from whichhydrocarbons may flow into higher conductive fracture pathways. Further,such fluids introduce less residual damage into the formation in lightof the absence of viscosifying polymer in the fluid.

In some shale formations, an excessively long primary fracture oftenresults perpendicular to the minimum stress orientation. Typically,pumping of additional fracturing fluid into the wellbore simply extendsthe planar or primary fracture. In most instances, primary fracturesdominate and secondary fractures are limited. Fracturing treatmentswhich create predominately long planar fractures are characterized by alow contacted fracture face surface area, i.e., low SRV. Production ofhydrocarbons from the fracturing network created by such treatments islimited by the low SRV.

Lately, slickwater fracturing has been used in the treatment of shaleformations. However, the secondary fractures created by the operationare near to the wellbore where the surface area is increased. Slickwaterfracturing is generally considered to be inefficient in the opening orcreation of complex network of fractures farther away from the wellbore.Thus, while SRV is increased in slickwater fracturing, production ishigh only initially and then drops rapidly to a lower sustainedproduction since there is little access to hydrocarbons far field fromthe wellbore.

Like slickwater fracturing, conventional fracturing operations typicallyrender an undesirably lengthy primary fracture. While a greater numberof secondary fractures may be created farther from the wellbore usingviscous fluids versus slickwater, fluid inefficiency, principallyexhibited by a reduced number of secondary fractures generated near thewellbore, is common in conventional hydraulic fracturing operations.

Recently, attention has been directed to alternatives for increasing theproductivity of hydrocarbons far field from the wellbore as well as nearwellbore. Particular attention has been focused on increasing theproductivity of low permeability formations, including shale. Methodshave been especially tailored to the stimulation of discrete intervalsalong the horizontal wellbore resulting in perforation clusters. Whilethe SRV of the formation is increased by such methods, potentiallyproductive reservoir areas between the clusters are often notstimulated. This decreases the efficiency of the stimulation operation.Methods of increasing the SRV by increasing the distribution of the areasubjected to fracturing have therefore been sought.

SUMMARY OF THE INVENTION

The complexity of a fracture network may be enhanced during a hydraulicfracturing operation by monitoring operational parameters of thefracturing job and altering stress conditions in the well during theoperation. In addition, the total surface area of the created fracturemay be increased by such operations. The method provides an increase tothe stimulated reservoir volume (SRV).

One or more operational parameters may be monitored. The commonoperational parameters which are monitored are the injection rate of thefluid, the density of the fluid and the bottomhole pressure of the well.

One or more operational parameters are assessed before a fluid stage ispumped and after the fluid stage is pumped. Stress conditions within thewell may then be altered based on the difference between the monitoredreading of the operational parameter after pumping of the fluid stageand a pre-determined target of the operational parameter. Thus,subsequent steps in the hydraulic fracturing operation are determined bythe responses observed from monitoring one or more operationalparameter(s).

In one embodiment, the operational parameter is monitored after theinitial fracturing fluid or pad fluid is pumped into the formation whichenlarges or creates initial fracture.

In another embodiment, the operational parameter may be monitored afterany fluid stage which is pumped into the formation after the initialfracturing fluid or pad fluid.

In another embodiment, the operational parameter may be monitored duringeach fluid stage which is pumped into the formation.

When the operational parameter being monitored is different from thetargeted operational parameter, the flow of fluid entering the formationmay be diverted.

In one embodiment, the flow of fluid from a highly conductive primaryfracture or fractures to lower conductive secondary fractures may bediverted after the operational parameter has been monitored.

In an embodiment, the flow of fluid into the formation may be divertedby changing the rate of injection of the fluid which is pumped into theformation after the operational parameter is monitored.

In another embodiment, the flow of fluid may be diverted by pumping intothe formation, after the monitored stage is pumped, a diversion fluidwhich contains a chemical diverting agent.

In an embodiment, the chemical diverter used in the method describedherein may be a compound of the formula:

or an anhydride thereof

wherein:

-   -   R¹ is —COO—(R⁵O)_(y)—R⁴;    -   R² and R³ are selected from the group consisting of —H and        —COO—(R⁵O)_(y)—R⁴;        -   provided that at least one of R² or R³ is —COO—(R⁵O)_(y)—R⁴            and further provided that both R² and R³ are not            —COO—(R⁵O)_(y)—R⁴;    -   R⁴ is —H or a C₁-C₆ alkyl group;    -   R⁵ is a C₁-C₆ alkylene group; and    -   each y is 0 to 5;        In a preferred embodiment, the chemical diverter is phthalic        anhydride or terephthalic anhydride.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to more fully understand the drawings referred to in thedetailed description of the present invention, a brief description ofeach drawing is presented, in which:

FIG. 1 is a flow diagram of the method of the invention whereincontinuous stages are pumped into a subterranean formation to enhance afracture network.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Illustrative embodiments of the invention are described below as theymight be employed in the operation and treatment of oilfieldapplications. In the interest of clarity, not all features of an actualimplementation are described in this specification. It will of course beappreciated that in the development of any such actual embodiment,numerous implementation and/or specific decisions must be made toachieve the specific goals of the operator, which will vary from oneimplementation to another. Moreover, it will be appreciated that such adevelopment effort might be complex and time-consuming, but maynevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure. Further aspects andadvantages of the various embodiments of the invention will becomeapparent from consideration of the following description.

Steps of the hydraulic fracturing methods described herein are premisedon results obtained from monitoring of one or more operationalparameters during treatment of the well. The methods may be used toextend fractures or create a multiple network of fractures. As such, themethods may be used to enhance the complexity of a fracture networkwithin a subterranean formation and to enhance production ofhydrocarbons from the formation.

In the methods described herein, one or more operational parameters of ahydraulic fracturing operation are monitored after completion of a fluidpumping stage. In particular, the operational parameters are compared totargeted parameters pre-determined by the operator. Based on thecomparison, stress conditions in the well may be altered beforeintroduction of a successive fluid stage into the formation.

The term “successive fluid pumping stage” as used herein refers to thefluid pumping stage in a hydraulic fracturing operation which precedesanother fluid pumping stage. The fluid pumping stage which immediatelyprecedes the successive fluid pumping stage is referred to as the“penultimate fluid pumping stage”. Since the methods described hereinmay be a continuous operation or have repetitive steps, a successivefluid pumping stage may be between two penultimate fluid pumping stages.For example, a first successive fluid pumping stage may follow a firstpenultimate fluid pumping stage. When referring to a “second successivefluid pumping stage”, the first successive fluid pumping stage is thesecond penultimate fluid pumping stage and so on. A successive fluidpumping stage may be pumped into the wellbore following a period of timefor the fluid of the penultimate fluid pumping stage to be diverted intothe fracture created or enlarged by the penultimate fluid pumping stage.

Stress within the well may be determined by monitoring one or moreoperational parameters. Changes in one or more of the operationalparameters are indications to the operator that fracture complexityand/or fracture geometry has changed and that Stimulated ReservoirVolume (SRV) has increased. For instance, stress noted within theformation may be indicative as to propagation of the fracture. Themethod of assessing stress within the well may include real-timemodeling of the created fracture network using a simulator, such asMShale.

Thus, observance of trends and responses of operational parametersresulting from a penultimate fluid pumping stage may be used to controland dictate conditions of successive fluid pumping stage.

For instance, variances between one or more pre-determined operationalparameters with the operational parameter after a second successivefluid pumping stage may indicate to the operator whether fractures havebeen created or whether fluid has been lost during the secondpenultimate fluid pumping stage to intercepting fractures.

Based upon the change in one or more of the operational parameters,stress within the reservoir may be altered. For instance, wherepropagation is insufficient as determined by the operator after a fluidpumping stage, the operator may cause an alteration of the reservoirstress field. The methods defined herein may thus be used to increasethe complexity of the fractures by artificially adding a resistance inthe fracture such that new fracture paths are opened that wouldotherwise not be able to be created or enlarged. Thus, fracturecomplexity may be increased as the differential stress or propagationpressure increases. This may occur without a sustained increase infracturing pressure.

In a preferred embodiment, one or more of the following operationalparameters are monitored during the fracturing operation: the rate ofinjection of the fluid, the bottomhole pressure of the well (measured asNet Pressure) or the density of the fluid pumped into the formation. Themonitoring of such operational parameter(s) may be used to create anetwork of fractures at near-wellbore as well as far-wellbore locationsby altering stress conditions within the reservoir.

The injection rate of the fluid is defined as the maximum rate ofinjection that the fluid may be pumped into the formation beyond whichthe fluid is no longer capable of fracturing the formation (at a givenpressure). The maximum rate of injection is dependent on numerousconstraints including the type of formation being fractured, the widthof the fracture, the pressure which the fluid is pumped, permeability ofthe formation, etc. The maximum rate of injection is pre-determined bythe operator. Changes in Net Pressure are indications of change infracture complexity and/or change in fracture geometry thus producinggreater Stimulated Reservoir Volume (SRV). The Net Pressure that isobserved during a hydraulic fracturing treatment is the differencebetween the fluid pressure in the fracture and the closure pressure (CP)of the formation.

-   -   Fluid pressure in the fracture=Bottom Hole Treating Pressure        (BHTP).    -   BHTP can be calculated from: Surface Treating Pressure        (STP)+Hydrostatic Head (HH)−Total Delta Friction Pressures        (Δp_(friction)=pipe friction+perforation friction+tortuosity).

Determination of closure pressure, pipe friction, perforation friction,and presence of tortuosity is critical. A diagnostic treatment using astep down rate and observance of pressure decline should be conducted ifthe formation can sustain a pumping shut down without limiting thedesired injection rate upon restarting the injection to obtain thesenecessary parameters. The bottomhole pressure (also known as themeasured or calculated bottomhole pumping pressure or measured orcalculated bottomhole treating pressure) (BHP) is a measurement orcalculation of the fluid pressure in a fracture. It is needed todetermine the Net Pressure defined as:

P _(net) =STP+HH−P _(fric) −CP

Although many conventional fracture treatments result in bi-wingfractures, there are naturally fractured formations that provide thegeomechanical conditions that enable hydraulically induced discretefractures to be initiated and propagate in multiple planes as indicatedby microseismic mapping. The dominant or primary fractures propagate inthe x-z plane perpendicular to the minimum horizontal stress, o.₃. They-z and x-y plane fractures propagate perpendicular to the o.₂ and o.₁,stresses, respectively. The discrete fractures created in the x-z andy-z planes are vertical, while the induced fractures created in the x-yplane are horizontal. The microseismic data collected during a fracturetreatment can be a very useful diagnostic tool to calibrate the fracturemodel by inferring DFN areal extent, fracture height and half-length andfracture plan orientation. Integrating minifrac analysis, hydraulicfracturing and microseismic technologies with the production responsefor multiple transverse vertical fractures provides a methodology toimprove the stimulation program for enhanced gas production.

Programs or models for modeling or predicting BHP are known in the art.Examples of suitable models include, but are not limited to, “MACID”employed by Baker Hughes Incorporated and available from Meyer andAssociates of Natrona Heights, Pa.; “FRACPRO” from Resources EngineeringServices; and “FRACPRO PT”, available from Pinnacle Technology. BHP mayfurther be calculated based on formation characteristics. See, forinstance, Hannah et al, “Real-time Calculation of Accurate BottomholeFracturing Pressure From Surface Measurements Using Measured Pressuresas a Base”, SPE 12062 (1983); Jacot et al, “Technology Integration—AMethodology to Enhance Production and Maximize Economics in HorizontalMarcellus Shale Wells”, SPE 135262 (2010); and Yeager et al,“Injection/Fall-off Testing in the Marcellus Shale: Using ReservoirKnowledge to Improve Operational Efficiency”, SPE 139067 (2010).

The objective is therefore to observe changes in one or more of theoperational parameters and alter the operational parameter(s) responseby using diversion. The value of that change will be formation and areaspecific and can even vary within the same formation within the samelateral. Those differences arise in the varying minimum and maximumstress planes. In some instances there is very low anisotropy resultingin “net” fracture development. In other areas the anisotropy is veryhigh and a conventional profile may dominate the fracture complexity.

Since the presence of low to high anisotropy, as well as anisotropy inbetween low anisotropy and high anisotropy, can often not be ascertainedthrough a mini-frac treatment, net pressure changes are often the keyoperational parameter used to assess stress conditions. Downward slopes,negative, are indications of height growth while positive slopes of <45°will be indications of height and extension growth depending on slope.Thus, changes in one or more of the operational parameters may beindicative of fracture height and growth. For instance, while smallchanges in BHP may be due to varying frictional pressures of fluids (andproppants) as the fluid travels through the fracture system, sustainednegative downward slopes may be indicative of height growth, positiveslopes of less than 45° may be indicative of height and extensiongrowth.

Stress conditions in the well may be altered by diverting fluid flowsuch that the fluid pumped into the formation will more readily flowinto less conductive secondary fractures within the formation. Suchdiversion limits injectivity in the primary fractures and stresspressures within the formation. As such, fluid flow may be diverted froma highly conductive primary fracture(s) to less conductive secondaryfractures. Since conductivity is permeability multiplied by injectiongeometry, this is synonymous to the statement that fluid flow may bediverted from a high permeability zone to a low permeability zone.Further, since conductivity is a function of the relative resistance toinflow, the reference to a conductive fracture as used herein isconsidered synonymous to a conductive reservoir area. Alteration of thelocal stress conditions provides greater complexity to the createdfracture network and/or improves the reservoir coverage of thestimulation treatment.

Thus, the methods described herein can be used to extend or increase afracture profile. In addition, the methods described herein may be usedto create a multiple of fractures originating from the original primaryfracture wherein each successive stage creates a fracture having anorientation distinct from the directional orientation of the fracturecreated by the penultimate fracture.

When necessary, the flow of fluid within the formation may be divertedby subjecting the formation to one or more diversion stages.

Fluid flow may be diverted from highly conductive fractures to lessconductive fractures by changing the injection rate and viscosity of thefluid into the formation.

Diversion may also occur by introduction of a diverter fluid or slugcontaining a chemical diverting agent into the formation. This may causedisplacement of the diverter slug beyond the near wellbore.

Further, a combination of a diverter fluid or slug may be used with achange in the injection rate and/or viscosity of fluid into theformation in order to effectuate diversion from a highly conductivefracture to a less conductive fracture. The diverter fluid may contain achemical diverting agent. The diverter fluid may be pumped into theformation at a rate of injection which is different from the rate ofinjection of a penultimate fluid pumping stage but rate is necessarilylimited to a rate low enough so as not to exceed the predeterminedpressure limitations observed with the surface monitoring equipment.

The diversion stage serves to divert fluid flow away from highlyconductive fractures and thus promotes a change in fracture orientation.This causes fluid entry and extension into the secondary fractures. Forinstance, a reduction in injection rate may be used to allow the shearthinning fluid to build sufficient low shear rate viscosity for adequatepressure diversion for the changing fracture orientation created by thesecondary fractures. In addition, reduction in injection rate maycontribute to the opening and connecting of secondary fractures.

In an embodiment, diversion fluid and/or the change in injection rate ofpumped fluid may create at least one secondary fracture in a directionalorientation distinct from the directional orientation of the primaryfracture. Thus, at some point along the primary fracture the resistanceto flow of the viscosity and resultant increased pressure induces thesuccessive stage fluid to be diverted to a new area of the reservoirsuch that the increase in SRV occurs.

After diversion, the flow of fluid introduced into the low permeabilityzone of the formation may be impeded. The operational parameter beingmonitored may then be compared to the pre-determined operationalparameter. Subsequent fluid stages may be introduced into the formationand the need for diversionary stages will be premised on the differencebetween the monitored operational parameter following the subsequentfluid stage with the targeted operational parameter.

After the diverter fluid is pumped or after the injection rate of fluidinto the formation is modified, the operational parameter beingmonitored may then be noted. If the operational parameter is less thanthe target of the operational parameter, the fluid flow may continue tobe diverted in another diversionary step.

The process may be repeated until the SRV desired is obtained or untilthe complexity of the fracture is attained which maximizes theproduction of hydrocarbons from the formation.

Thus, by monitoring an operational parameter and observing changes inthe operational parameter, stresses within the formation may be altered.The value of any diversionary step will be formation and area specificand differences may be noted in varying minimum and maximum stressplanes within the same lateral. For instance, in some instances very lowanisotropy will result in net fracture development. In other areas veryhigh anisotropy may dominate the fracture complexity.

In one preferred embodiment, the bottomhole pressure of fluid afterpumping a first stage is compared to the targeted pre-determinedbottomhole pressure of the well. The first stage may be the stage whichenlarges or creates a fracture. Based on the difference in thebottomhole pressure, the flow of fluid from a highly conductive primaryfracture to less conductive secondary fractures may be diverted byintroducing into the formation a chemical diverter. The bottomholepressure after the diversion may then be compared to the pre-determinedbottomhole pressure. The flow of fluid introduced into the lowconductive fracture in the next stage may then be impeded. Subsequentfluid stages may be introduced into the formation and the need forsubsequent diversionary stages will be premised on the differencebetween the bottomhole pressure after a preceding stage and thepre-determined bottomhole pressure.

In another preferred embodiment, the maximum injection rate which afluid may be pumped after the pumping of a first fluid stage is comparedto the targeted injection rate. The first stage may be the stage whichenlarges or creates a fracture. Based on the difference in the rates ofinjection, the flow of fluid from a highly conductive primary fractureto less conductive secondary fractures may be diverted by introducinginto the formation a chemical diverter. The maximum rate of injectionafter the diversion may then be compared to the pre-determined rate ofinjection. The flow of fluid introduced into the low conductive fracturein the next stage may then be impeded. Subsequent fluid stages may beintroduced into the formation and the need for subsequent diversionarystages will be premised on the difference between the maximum rate ofinjection after a preceding stage and the pre-determined injection rate.

In another preferred embodiment, the density of a fluid stage afterpumping a first stage is compared to a targeted density of a fluidstage. Based on the difference in fluid density, the flow of fluid froma highly conductive primary fracture to less conductive secondaryfractures may be diverted by the injection rate of the fluid or byintroduction of a chemical diverter into the formation. The density ofthe fluid stage after the diversion may then be compared to thepre-determined fluid density. The flow of fluid introduced into the lowconductive fracture in the next stage may then be impeded. Subsequentfluid stages may be introduced into the formation and the need fordiversionary stages will be premised on the difference between the fluidstage density after a preceding stage and the pre-determined fluiddensity.

In an embodiment, the diversion fluid pumped into the formation inresponse to a monitored operational parameter may contain a chemicaldiverter (which may be partially, but not fully, dissolved in at in-situreservoir conditions) in combination with relatively lightweightparticulates having an apparent specific gravity less than or equal to2.45. Preferably, relatively lightweight particulates are neutrallybuoyant in the fluid which further contains the chemical diverter.

Chemical diverters, optionally in combination with relativelylightweight particulates, may be used to control fluid loss to naturalfractures and may be introduced into productive zones of a formationhaving various permeabilities. The diverter, optionally in combinationwith relatively lightweight particulates, is capable of diverting a welltreatment fluid from a highly conductive fracture to less conductivefractures within a subterranean formation.

The diverter may be partially, but not fully, dissolvable in fluids atin-situ reservoir conditions. Any portion of the diverter which remainsas an undissolved confined particulate, after being pumped into theformation, may function as a proppant. The amount of diverter which isdissolvable in at in-situ conditions is typically from about 75% toabout 95%. Preferably, the amount of the diverter which is dissolvablein the fluid is about 90%. At such concentrations, a partial monolayerof the diverter may function as proppant. Over time, all of the divertermay eventually dissolve when fracture closure no longer presents aconcern to the operator.

The solid particulates typically bridge the flow spaces on the face ofthe formation and form a filter cake. For instance, when employed inacid fracturing, the particulates are of sufficient size to bridge theflow space (created from the reaction of the injected acid with thereservoir rock) without penetration of the matrix. By being filtered atthe face of the formation, a relatively impermeable or low permeabilityfilter cake is created on the face of the formation. The pressureincrease through the filter cake also increases the flow resistance anddiverts treatment fluid to less permeable zones of the formation.

The size distribution of the particulates should be sufficient to blockthe penetration of the fluid into the high permeability zone of theformation. The filter cake is more easily formed when at least 60%, morepreferably 80%, of the chemical diverter and/or relatively lightweightparticulates within the well treatment fluid have a particle sizebetween from about 150 μm to about 2000 μm.

When used in stimulation operations, the particle size of theparticulates is such that the particulates may form a bridge on the faceof the rock. Alternatively, the particle size of the particulates may besuch that they are capable of flowing into the fracture and thereby packthe fracture in order to temporarily reduce the conductivity of at leastsome of the fractures in the formation.

Relatively lightweight particulates may also serve as proppant in any ofthe fluid stages introduced into the formation. In addition,conventional proppants, such as bauxite and sand may be used as proppantin any of the fluid stages.

The first stage may consist of pumping into the formation a fluid at apressure sufficient to either propagate or enlarge a primary fracture.This fluid may be a pad fluid. Fracture conductivity may be improved bythe incorporation of a small amount of proppant in the fluid. Typically,the amount of proppant in the pad fluid is between from about 0.12 toabout 24, preferably between from about 0.6 to about 9.0, weight percentbased on the total weight percent of the fluid.

Following the injection of the pad fluid, a viscous fluid may then beintroduced into the wellbore. The viscous fluid typically has aviscosity greater than about 10,000 cP at a shear rate of 0.01 sec⁻¹.The diversion stage may be pumped into the formation after the firststage or between any of the successive stages or penultimate stages.

Between any penultimate stage and successive stage, pumping may bestopped and a pad fluid containing a proppant may be pumped into thereservoir to assist in the creation or enlargement of secondaryfractures.

In a preferred embodiment, the proppant is a relatively lightweight orsubstantially neutrally buoyant particulate material or a mixturethereof. Such proppants may be chipped, ground, crushed, or otherwiseprocessed. By “relatively lightweight” it is meant that the proppant hasan apparent specific gravity (ASG) that is substantially less than aconventional proppant employed in hydraulic fracturing operations, e.g.,sand or having an ASG similar to these materials. Especially preferredare those proppants having an ASG less than or equal to 3.25. Even morepreferred are ultra lightweight proppants having an ASG less than orequal to 2.25, more preferably less than or equal to 2.0, even morepreferably less than or equal to 1.75, most preferably less than orequal to 1.25 and often less than or equal to 1.05.

The proppant may further be a resin coated ceramic proppant or asynthetic organic particle such as nylon pellets, ceramics. Suitableproppants further include those set forth in U.S. Patent Publication No.2007/0209795 and U.S. Patent Publication No. 2007/0209794, hereinincorporated by reference. The proppant may further be a plastic or aplastic composite such as a thermoplastic or thermoplastic composite ora resin or an aggregate containing a binder.

By “substantially neutrally buoyant”, it is meant that the proppant hasan ASG close to the ASG of an ungelled or weakly gelled carrier fluid(e.g., ungelled or weakly gelled completion brine, other aqueous-basedfluid, or other suitable fluid) to allow pumping and satisfactoryplacement of the proppant using the selected carrier fluid. For example,urethane resin-coated ground walnut hulls having an ASG of from about1.25 to about 1.35 may be employed as a substantially neutrally buoyantproppant particulate in completion brine having an ASG of about 1.2. Asused herein, a “weakly gelled” carrier fluid is a carrier fluid havingminimum sufficient polymer, viscosifier or friction reducer to achievefriction reduction when pumped down hole (e.g., when pumped down tubing,work string, casing, coiled tubing, drill pipe, etc.), and/or may becharacterized as having a polymer or viscosifier concentration of fromgreater than about 0 pounds of polymer per thousand gallons of basefluid to about 10 pounds of polymer per thousand gallons of base fluid,and/or as having a viscosity of from about 1 to about 10 centipoises. Anungelled carrier fluid may be characterized as containing about 0 to <10pounds of polymer per thousand gallons of base fluid. (If the ungelledcarrier fluid is slickwater with a friction reducer, which is typicallya polyacrylamide, there is technically 1 to as much as 8 pounds ofpolymer per thousand gallons of base fluid, but such minuteconcentrations of polyacrylamide do not impart sufficient viscosity(typically<3 cP) to be of benefit).

Other suitable relatively lightweight proppants are those particulatesdisclosed in U.S. Pat. Nos. 6,364,018, 6,330,916 and 6,059,034, all ofwhich are herein incorporated by reference. These may be exemplified byground or crushed shells of nuts (pecan, almond, ivory nut, brazil nut,macadamia nut, etc); ground or crushed seed shells (including fruitpits) of seeds of fruits such as plum, peach, cherry, apricot, etc.;ground or crushed seed shells of other plants such as maize (e.g. corncobs or corn kernels), etc.; processed wood materials such as thosederived from woods such as oak, hickory, walnut, poplar, mahogany, etc.including such woods that have been processed by grinding, chipping, orother form of particalization. Preferred are ground or crushed walnutshell materials coated with a resin to substantially protect and waterproof the shell. Such materials may have an ASG of from about 1.25 toabout 1.35.

Further, the relatively lightweight particulate for use in the inventionmay be a selectively configured porous particulate, as set forth,illustrated and defined in U.S. Pat. No. 7,426,961, herein incorporatedby reference.

In a preferred embodiment, at least one diversion step in the methoddescribed herein consists of pumping into the formation a fluidcontaining a chemical diverter in combination with non-dissolvablerelatively lightweight particulates including those referenced above.The chemical diverting agent may be partially, but not fully,dissolvable at in-situ reservoir conditions. In another preferredembodiment, the diverting stage contains a chemical diverter with arelatively lightweight particulate substantially naturally buoyant inthe fluid.

The fluid phase of the treatment fluid containing the particulates isany fluid suitable for transporting the particulate into a well and/orsubterranean formation such as water, salt brine and slickwater.Suitable brines including those containing potassium chloride, sodiumchloride, cesium chloride, ammonium chloride, calcium chloride,magnesium chloride, sodium bromide, potassium bromide, cesium bromide,calcium bromide, zinc bromide, sodium formate, potassium formate, cesiumformate, sodium acetate, and mixtures thereof. The percentage of salt inthe water preferably ranges from about 0% to about 60% by weight, basedupon the weight of the water.

The fluid of the treatment fluid may be foamed with a liquid hydrocarbonor a gas or liquefied gas such as nitrogen or carbon dioxide.

In addition, the fluid may further be foamed by inclusion of anon-gaseous foaming agent. The non-gaseous foaming agent may beamphoteric, cationic or anionic. Suitable amphoteric foaming agentsinclude alkyl betaines, alkyl sultaines and alkyl carboxylates, such asthose disclosed in U.S. Patent Publication No. 2010/0204069, hereinincorporated by reference. Suitable anionic foaming agents include alkylether sulfates, ethoxylated ether sulfates, phosphate esters, alkylether phosphates, ethoxylated alcohol phosphate esters, alkyl sulfatesand alpha olefin sulfonates. Suitable cationic foaming agents includealkyl quaternary ammonium salts, alkyl benzyl quaternary ammonium saltsand alkyl amido amine quaternary ammonium salts.

The pH of the fluid containing the particulates may further be adjustedwhen desired. When adjusted, it typically has a value of about 6.5 ormore, 7 or more, 8 or more, 9 or more, between 9 and 14, and, mostpreferably, between 7.5 and 9.5. The pH may be adjusted by any meansknown in the art, including adding acid or base to the fluid, orbubbling carbon dioxide through the fluid.

The fluid may be gelled or non-gelled. Typically the fluid is gelled bythe inclusion of a viscosifying agent such as a viscosifying polymer orviscoelastic fluid. The fluid may contain a crosslinking agent though acrosslinking agent is not required. Generally, the viscosity of thefluid is greater than or equal to 10 cP at room temperature.

An illustrative process defined herein is shown in FIG. 1 wherein theoperational parameter being monitored is Net Pressure and wherein thefluid volume of each of the stages has been set by an operator; thetotal volume of the fluid being broken into four or more stages. Eachstage may be separated by a period of reduced or suspended pumping for asufficient duration to allow the staged fluid in the reservoir to flowinto a created or enlarged fracture.

The injection rate and the STP are established by the operator. Thefracturing operation is initialized by pumping into the formation afirst fluid stage comprising a pad fluid or slickwater. The Net Pressureresponse of the treatment is monitored. A plot of Net Pressure versestime on a log-log scale may be used to identify trends during thetreatment. At the end of the fluid pumping stage, the net pressure valueand slope is evaluated.

Where the pressure is equal to or greater than the pre-determined BHP,then additional fracturing fluid is pumped into the formation as asecond or successive stage and it is not necessary to divert the flow offluid from a high permeability zone to a lower permeability zone. Wherethe BHP (as measured by net Pressure) is less than the pre-determinedBHP, then a diverter fluid containing a chemical diverting agent or slugis pumped into the formation. The divert slug is displaced beyond nearwellbore. The diverter fluid may be over-displaced beyond the wellboreand into the fracture network. The net pressure response is thenobserved when the diversion stage is beyond the wellbore and in thefracture network. If the net pressure response is considered to besignificant by the operator indicating a change in fracture complexityand/or geometry then an additional fracturing fluid is pumped into theformation in order to stimulate a larger portion of the reservoir. Atthe end of pumping stage, net pressure is again evaluated and thepossibility of running another diversion stage is evaluated. If the netpressure response is not considered to be significant by the operator,then an additional diversion stage is pumped into the formation and thenet pressure response is evaluated when the diversion stage is beyondthe wellbore and in the fracture network. The volume and quantity of thesuccessive diversion stage may be the same as the penultimate diversionstage or may be varied based on the pressure response. The injectionrate of the pumped fluid may also be changed once the diversion stage isin the fracture system to affect the pressure response. If the netpressure response is too significant in size indicating a bridging ofthe fracture without a change in fracture complexity and/or geometry,additional pumping may or may not be warranted. For example if thepressure response is too high the pressure limitations of the tubularsmay prevent a continuation of the treatment due to rate and formationinjectivity limitations. The running of additional diversion stages maybe repeated as necessary until a desired pressure response is achievedand the fracture complexity/geometry is maximized, the well treatmentinjection is ceased and the well may then be shut in, flowed back orsteps may be undertaken to complete subsequent intervals

If the BHP is less than the pre-determined BHP, then a successive stageis pumped into the formation and the process repeated. The process maybe continuous and may be repeated multiple times throughout the courseof the pumping treatment to attain development of a greater fracturearea and greater fracture complexity than that which would be attainedin the absence of such measures.

The diversion stage either achieves or directly impacts the monitoredBHP so as to artificially increase the differential pressure. Thisdifferential pressure may not be obtained without the diverting fluid.The increased pressure differential causes sufficient stressdifferential to create or enlarge a smaller fracture. The effectivenessof the diversion may then be ascertained by either increasing the volumeof a chemical diverter or the size of the chemical diverter. Theincrease in BHP from the diverting stage limits the fluid volumeintroduced into the formation which would otherwise be larger volume.Thus, a benefit of the process is that a decreased amount of water maybe used to achieve a given degree of stimulation.

In place of the BHP, other parameters, such as fluid density andinjection rate of the fluid, may be used as the operational parameter inFIG. 1. With any of these parameters, the operator will determine thetargeted level based on the characteristics of the well and formationbeing treated. Reduction of the injection rate of the fluid further mayfacilitate the diversion of flow from narrow intersecting fracturesespecially when accompanied by increases in the treating pressure. Anincrease in the injection rate of the fluid renders greater propagationin the more primary fractures within the formation.

The diverter of the diversion fluid for use in the invention may be anydiverter known in the art. Especially preferred as diverter are thoseparticulates having the structural formula (I):

wherein:

-   -   R¹ is —COO—(R⁵O)_(y)—R⁴;    -   R² and R³ are selected from the group consisting of —H and        —COO—(R⁵O)_(y)—R⁴;        -   provided that at least one of R² or R³ is —COO—(R⁵O)_(y)—R⁴            and further provided that both R² and R³ are not            —COO—(R⁵O)_(y)—R⁴;    -   R⁴ is —H or a C₁-C₆ alkyl group;    -   R⁵ is a C₁-C₆ alkylene group; and    -   each y is 0 to 5.        Alternatively, the particulates may be an anhydride of the        compound of structural formula (I).

In a preferred embodiment, R² of the compound of formula (I) is —H andR³ is —COO—(R⁵O)_(y)—R⁴. In an especially preferred embodiment, thecompound of formula (I) is phthalic acid (wherein y is 0 and R⁴ is —H).In another preferred embodiment, the compound of formula (I) is phthalicacid anhydride.

Still in another preferred embodiment, R² of the compound of formula (I)is —COO—(R⁵O)_(y)—R⁴ and R² is —H. In an especially preferredembodiment, the compound of formula (I) is terephthalic acid (wherein yis 0 and R⁴ is —H). In another preferred embodiment, the compound offormula (I) is terephthalic acid anhydride.

Such diverters and fluids containing the same are set forth in the U.S.patent application entitled Method of Using Phthalic and TerephthalicAcids and Derivatives Thereof in Well Treatment Operations (inventor: D.V. Satyanarayana Gupta) which is filed concurrently with the instantapplication and which is herein incorporated by reference.

The particulates may be of any size or shape and the particulates withina given diversionary stage may be of varying size. For instance, theparticulates may be substantially spherical, such as being beaded, orpelleted. Further, the particulates may be non-beaded and non-sphericalsuch as an elongated, tapered, egg, tear-drop or oval shape or mixturesthereof. For instance, the particulates may have a shape that is cubic,bar-shaped (as in a hexahedron with a length greater than its width, anda width greater than its thickness), cylindrical, multi-faceted,irregular, or mixtures thereof. In addition, the particulates may have asurface that is substantially roughened or irregular in nature or asurface that is substantially smooth in nature. Moreover, mixtures orblends of particulates having differing, but suitable, shapes for use inthe disclosed method further be employed.

The amount of particulates of formula (I) in the diversion fluid may befrom about 0.01 to about 30 volume percent (based on the total volume ofthe fluid) and may be partially dissolvable at in-situ downholeconditions. In some instances, the particulates of formula (I) are fullydissolvable at downhole conditions.

The particulates are particularly effective when placed into wellshaving bottomhole temperatures between from about 175° F. to about 250°F.

When used as a diverter, the fluid containing the particulates may alsobe pumped directly to the high permeability zone of the well formation.The majority of the diverting fluid will enter into the highpermeability or non-damaged zone and form a temporary “plug” or “viscouspill” while the lower permeability zone has little invasion. Thistemporary “viscous pill” causes a pressure increase and diverts thefluid to a lower permeability portion of the formation. The particulatesare capable of being spread deeper into subterranean formations thandiverting agents of the prior art.

Once in place, the viscous pill formed from the diverter will have afinite depth of invasion which is related to the pore throat diameter.For a given formation type, the invasion depth is directly proportionalto the nominal pore throat diameter of the formation. Since varyingdepths of invasion occur throughout the formation based upon the varyingpermeability or damage throughout the treated zone, the ability of thetreatment fluid to invade into pore throats is dependent on thedifference between pore throat sizing of the damaged and non-damagedformation. Invasion depths will normally be greater in the cleaner ornon-damaged portion of the formation (larger pore throats) than in thelower permeability or damaged zones (smaller or partially filled porethroats). With a greater depth of invasion in the cleaner sections ofthe formation, more of the diverter may be placed in these intervals.

The methods described herein may be used in the fracturing of formationspenetrated by horizontal as well as vertical wellbores.

The formation subjected to the treatment of the invention may be ahydrocarbon or a non-hydrocarbon subterranean formation. The highpermeability zone of the formation into which the fluid containing thediverter is pumped may be natural fractures. When used with lowviscosity fracturing fluids, the particulates of formula (I) are capableof diverting fracturing fluids to extend fractures and increase thestimulated surface area.

The invention has particular applicability to the stimulation ofcarbonate formations, such as limestone, chalk or dolomite as well assubterranean sandstone or siliceous formations in oil and gas wells,including quartz, clay, shale, silt, chert, zeolite, or a combinationthereof.

In another preferred embodiment, the method may be used in the treatmentof coal beds having a series of natural fractures, or cleats, for therecovery of natural gases, such as methane, and/or sequestering a fluidwhich is more strongly adsorbing than methane, such as carbon dioxideand/or hydrogen sulfide.

From the foregoing, it will be observed that numerous variations andmodifications may be effected without departing from the true spirit andscope of the novel concepts of the invention.

What is claimed is:
 1. A method of hydraulically fracturing ahydrocarbon-bearing subterranean formation penetrated by a reservoirwhich comprises: (a) pumping a fluid into the formation at a pressuresufficient to create or enlarge a primary fracture; (b) determining abottomhole treating pressure within the well; (c) diverting the flow offluid from loss zones by introducing into the formation a chemicaldiverter; (d) comparing the determined bottomhole treating pressure witha pre-determined targeted bottomhole treating pressure; (e) pumping afracturing fluid into the formation, wherein the flow of the fracturingfluid to the loss zone is impeded by the chemical diverter, and (f)extending the primary fracture in the formation.
 2. The method of claim1, wherein the chemical diverter of step (c) is introduced into theformation at an injection rate which is different from the injectionrate of the fluid pumped in step (a).
 3. The method of claim 1, whereinthe chemical diverter is removed subsequent to the treatment.
 4. Themethod of claim 1, wherein the chemical diverter is partially, but notfully, dissolvable at in-situ downhole reservoir conditions.
 5. Themethod of claim 1, wherein the chemical diverter is fully dissolvable atin-situ downhole reservoir conditions.
 6. The method of claim 1, whereinthe chemical diverter is a compound of the formula:

or an anhydride thereof wherein: R¹ is —COO—(R⁵O)_(y)—R⁴; R² and R³ areselected from the group consisting of —H and —COO—(R⁵O)_(y)—R⁴; providedthat at least one of R² or R³ is —COO—(R⁵O)_(y)—R⁴ and further providedthat both R² and R³ are not —COO—(R⁵O)_(y)—R⁴; R⁴ is —H or a C₁-C₆ alkylgroup; R⁵ is a C₁-C₆ alkylene group; and each y is 0 to
 5. 7. The methodof claim 6, wherein the chemical diverter is phthalic anhydride orterephthalic anhydride.
 8. A method of hydraulically fracturing ahydrocarbon-bearing subterranean formation penetrated by a well whichcomprises: (a) pumping a fluid into the formation at a pressuresufficient to create or enlarge a fracture; (b) determining a surfacepressure at or near the surface of the well; (c) diverting a flow offluid from highly conductive zones to less conductive zones byintroducing into the formation a diverting agent; (d) comparing thedetermined surface pressure with a targeted surface pressure; and (e)altering stress in the well and extending the fracture, wherein stressis altered in the well by varying at least one of the following: (i) theinjection rate of the fluid; (ii) the bottomhole pressure of the well;or (iii) the density of the fluid.
 9. The method of claim 8, whereinsteps (a) through (e) are continuous.
 10. The method of claim 8, whereinthe subterranean formation is shale.
 11. The method of claim 8, whereinthe diverting agent is a compound of the formula:

or an anhydride thereof wherein: R¹ is —COO—(R⁵O)_(y)—R⁴; R² and R³ areselected from the group consisting of —H and —COO—(R⁵O)_(y)—R⁴; providedthat at least one of R² or R³ is —COO—(R⁵O)_(y)—R⁴ and further providedthat both R² and R³ are not —COO—(R⁵O)_(y)—R⁴; R⁴ is —H or a C₁-C₆ alkylgroup; R⁵ is a C₁-C₆ alkylene group; and each y is 0 to
 5. 12. Themethod of claim 11, wherein the diverting agent is phthalic anhydride orterephthalic anhydride.
 13. The method of claim 8, wherein the fluid of(a) further comprises a proppant.
 14. The method of claim 13, whereinthe proppant has an apparent specific gravity less than or equal to2.25.
 15. A method of hydraulically fracturing a hydrocarbon-bearingsubterranean formation penetrated by a well wherein a fluid isintroduced into the well at a pressure sufficient to enlarge or create afracture, the method comprising: (a) defining at least one of thefollowing operational parameters: (i) an injection rate of the fluid,(ii) a density of the fluid; or (iii) a bottomhole treating pressure ofthe well (b) pumping the fluid into the formation and creating orenlarging a fracture; (b) comparing the difference between at least oneof the operational parameters of step (a) after the fluid is pumped intothe formation with the defined operational parameter; (c) altering theinjection rate of the fluid into the formation or pumping into theformation a diverting agent wherein the a flow of fluid introduced intothe formation is diverted from highly conductive fractures to lessconductive fractures; (d) comparing the difference between at least oneof the operational parameters of step (a) with the defined operationalparameters of step (a); (e) altering stress in the well and extendingthe fracture, wherein a stress is altered in the well by varying atleast one of the operational parameters of step (a) wherein, after step(e) the stimulated reservoir volume is greater than the stimulatedreservoir volume after step (c).
 16. The method of claim 15, wherein thesubterranean formation is shale.
 17. The method of claim 15, wherein adiverting agent is pumped into the formation in step (c).
 18. The methodof claim 17, wherein the diverting agent is a compound of the formula:

or an anhydride thereof wherein: R¹ is —COO—(R⁵O)_(y)—R⁴; R² and R³ areselected from the group consisting of —H and —COO—(R⁵O)_(y)—R⁴; providedthat at least one of R² or R³ is —COO—(R⁵O)_(y)—R⁴ and further providedthat both R² and R³ are not —COO—(R⁵O)_(y)—R⁴; R⁴ is —H or a C₁-C₆ alkylgroup; R⁵ is a C₁-C₆ alkylene group; and each y is 0 to
 5. 19. Themethod of claim 18, wherein the diverting agent is phthalic anhydride orterephthalic anhydride.
 20. A method of hydraulically fracturing ahydrocarbon-bearing subterranean formation penetrated by a wellcomprising: (a) pumping a fracturing fluid into the formation at apressure sufficient to create or enlarge a fracture; (b) pumping intothe formation a diverter fluid, wherein a flow of diverter fluidintroduced into the formation proceeds from a highly conductive zone toa less conductive zone; and (c) pumping into the formation additionalfracturing fluid at a pressure greater than the pressure defined in step(a) wherein the fracture area within the formation after step (c) isgreater than the fracture area created from a substantially similarmethod not employing step (b).
 21. A method of hydraulically fracturinga hydrocarbon-bearing subterranean formation penetrated by a well whichcomprises: (a) pumping a fluid into the formation at a pressuresufficient to create or enlarge a primary fracture; (b) monitoring anoperational parameter and comparing the operational parameter afterpumping of the fluid into the formation with a pre-determined value forthe operational parameter, wherein the operational parameter is at leastone of the following: (i) the injection rate of the fluid, (ii) thedensity of the fluid; or (iii) the bottomhole treating pressure of thewell (c) diverting the flow of fluid from a highly conductive zone to aless conductive zone by diversion; (d) comparing the operationalparameter after step (c) with the pre-determined value for theoperational parameter; (e) pumping a fracturing fluid into theformation, wherein the flow of the fracturing fluid to the lessconductive zone is impeded by the diverter; and (f) extending theprimary fracture in the formation.
 21. The method of claim 1, whereinthe diversion of step (c) includes pumping into the formation a chemicaldiverter.
 22. The method of claim 21, wherein a relatively lightweightparticulate is pumped into the formation with the chemical diverter.